Mark Latham Commodity Equity Intelligence Service

Friday 9th September 2016
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    La Nina Odds Dim, Clouding Winter Forecast for U.S. Gas Traders

    La Nina Odds Dim, Clouding Winter Forecast for U.S. Gas Traders

    The U.S. Climate Prediction Center has dropped its La Nina watch and now says there is a greater chance the weather-changing event that can boost U.S. natural gas prices won’t happen.

    There is a 35 to 45 percent chance a La Nina, characterized by cooling equatorial Pacific waters, will form by the end of the year, down from 75 percent in June, according to Michelle L’Heureux, a forecaster with the center in College Park, Maryland. Prospects for La Nina dimmed after models suggested the Pacific has reached its coolest phase for this cycle and will moderate through rest of 2016.

    La Ninas often deliver colder winters to the northern U.S., which can trigger higher gas prices by boosting demand for the power plant fuel. The event can also cause flooding in Australia’s coal belt or drought in Brazil’s soybean fields that can cut crop yields. If La Nina fails to arrive, predicting the weather in general becomes more difficult, according to L’Heureux.

    “We’re dropping the La Nina watch, but the chance of a La Nina itself is definitely not zero,” L’Heureux said.

    La Ninas typically occur every two to seven years when cooler sea surface temperatures trigger a reaction in the atmosphere. When the same area warms, its an El Nino. Either phenomenon makes weather forecasting easier, according to L’Heureux.

    Forecasters haven’t seen any changes in thunderstorms, winds or ocean temperatures pointing to a La Nina in the last month, according to the center’s monthly update Thursday.

    Greater Predictability

    When the Pacific is in its normal state, other harder-to-predict patterns set the stage for wetter or drier seasons or temperatures above or below historical norms. In North America, twin patterns known as the Arctic and North Atlantic Oscillations could hold sway over how cold the winter gets and how much gas is burned to heat homes and businesses. If the oscillations turn negative, more cold air will pool over the continent.

    In some cases, such weather patterns give forecasters only a few weeks before changes that can dominate North America’s weather move in.

    “We like El Nino and La Nina,” L’Heureux said. “It gives us predictability.”

    La Ninas can also decrease wind shear across the tropical Atlantic allowing more hurricanes to form. Shear, when winds blow at opposite directions or varying speeds at different altitudes, will often rip apart tropical systems.

    Last year’s El Nino was one of the three strongest on record, generating the hottest global temperatures in more than 130 years, according to the U.S. National Centers for Environmental Information in Asheville, North Carolina.
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    Chinese Central Bank Crushes Yuan Shorts, Launching Bitcoin Buying Spree

    With the Yuan having traded within fractions of what many consider a key psychological level for the USDCNY at 6.70, many traders expected that following the just concluded G-20 meeting in China, the PBOC would finally relent in its devaluation defense, and let the currency slide on through to the other side. Not only did that not happen, but overnight the Chinese Central bank unleashed one of the most furious attacks on currency Yuan shorts since the January devaluation scare when the cost of borrowing yuan in Hong Kong soared to a seven-month high amid.

    The overnight HIBOR, or Hong Kong Interbank Offered Rate, jumped - seemingly without reason - by 3.88% points to 5.45%, the most expensive since February, according to Treasury Markets Association data. Other tenors joined with the one-week rate rose 2.09% points to 4.06%.

    As Bloomberg confirms, the PBOC "may have tightened liquidity in the offshore yuan market to control declines following speculation that it would allow depreciation now that a Group of 20 summit is over, according to Mizuho Bank Ltd. The monetary authority drove offshore yuan borrowing costs to unprecedented levels in January in an effort to punish bears."

    The mechanics of the move, used often in January and February when the Yuan was seemingly sliding every day, are as follows (courtesy of Bloomberg): China’s central bank influences funding costs in Hong Kong by encouraging state-owned banks to hold back from loaning their excess yuan. A surge in yuan Hibor hurts bears in two ways: by increasing the cost to borrow the currency and sell it, and also by prompting lenders that want to avoid paying the higher rates to buy the yuan they need in the spot market instead, bolstering the exchange rate.

    Meanwhile, the bogeyman for China, capital outflows, continue, and as China reported on Wednesday, the latest foreign reserve total dipped by $16 billion to $3.185 trillion.

    While capital outflows have eased from record levels last year, firms and individuals still appear uncomfortable with exposure to China’s currency. A Bloomberg gauge of local companies’ willingness to convert foreign currencies into yuan is near a record low, while an unprecedented overseas acquisition binge suggests strong demand for exposure to foreign assets. A net $55 billion flowed out of China in July, compared with $49 billion in the previous month, according to calculations by Goldman Sachs.

    For now the PBOC has won the battle, however it will likely lose the war: as Frances Cheung, head of rates for Asia ex-Japan at SocGen told Bloomberg, "front-end forward points coming off earlier highs suggests the squeeze could be temporary. The less flush offshore yuan liquidity conditions - as various flows subside - could amplify the movement in front-end rates should there be a sudden need for liquidity."

    Meanwhile, just as the PBOC intervened in the FX market, a new leak sprung in a totall different place: just as the central bank was squeezing Yuan shorts in Hong Kong, Bitcoin soared higher by another 3%, driven by a surge in buying on the Chinese Huobi exchange, sending the price for the digital currency back to a 1 month high.

    As we first reported over a year ago, when it was trading at $230, bitcoin has become the "capital outflow alternative" of choice for numerous Chinese, and based on historical patterns, any time Chinese capital outflows spike, or the PBOC engages aggressively in preventing these, the price of bitcoin jumps, just as it did overnight.

    Going forward the PBOC may be forced to intervene not only in the spot FX markets but also to short BTC as the local population gets increasingly creative in finding ways to bypass China's great monetary firewall.

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    Mexico 2017 budget cuts to squeeze Pemex, primary surplus eyed

    Mexico's government on Thursday set out plans for a bigger-than-anticipated cut in public spending in 2017, with struggling state oil company Pemex earmarked for a 100 billion peso ($5.36 billion) reduction in funding.

    New Finance Minister Jose Antonio Meade said the budget foresaw planned spending cuts of 239.7 billion pesos ($12.83 billion), targeting a primary surplus of 0.4 percent of gross domestic product (GDP) in 2017. It would be the first such surplus since 2008.

    Of the cuts, 100 billion pesos fall on Pemex [PMX.UL], which is already facing a funding squeeze and has racked up multi-billion dollar losses for years. Since the government ended its oil and gas monopoly nearly three years ago, Pemex has faced stiff competition from the private sector.

    "Pemex is making the biggest contribution to the cuts," Meade said, presenting the budget proposal to Congress a day after he was sworn in as finance minister following the resignation of Luis Videgaray.

    In late 2013, the government threw open the industry to private capital to reverse a protracted slide in oil production, but falling crude prices have undermined those efforts.

    Currently running at some 2.16 million barrels per day (bpd), Mexican oil production will slip to an average of 1.928 million bpd in 2017, the budget forecasts. The last time Mexican crude output fell below 2 million bpd was in 1980.

    Still, the budget does foresee changes aimed at easing Pemex's heavy tax load.

    Less than two years remain before the next presidential election, and President Enrique Pena Nieto's government is struggling to ramp up economic growth, having fallen well short of its original ambition to achieve annual rates of 5-6 percent.

    Hurt by uneven U.S. demand for its goods, Mexico's economy shrank in the second quarter for the first time in three years.

    Next year, the budget foresees growth of between 2 and 3 percent, compared with 2.0-2.6 percent in 2016.

    Despite the 2017 cuts - well above the 175.1 billion the government eyed in April - non-discretionary spending was expected to rise by 144.3 billion pesos, inflated by higher financing costs and a slide in the peso's value.

    Next year the government foresees an overall deficit of 2.9 percent of GDP, 0.6 percentage points less than the 2016 target.

    The budget foresaw the peso averaging 18.2 per dollar in 2017, and an average price of $42 per barrel for Mexican crude, in line with the government's hedging program.

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    Oil and Gas

    Adios Algiers, oil options hint output deal may lie further ahead

    The oil options market indicates traders are not betting big on OPEC and rival Russia clinching a meaningful deal this month to control output, although investors have turned more optimistic.

    The oil price is heading for its first weekly rise in nearly a month after Saudi Arabia and Russia said on Monday they would work closely to monitor fundamentals and to recommend measures to ensure market stability, including a potential production freeze.

    OPEC member countries and Russia will meet on the sidelines of the International Energy Forum in Algiers later this month and have signalled a freeze could be on the agenda.

    The initial $2.50 gain in oil to a high of $49.40 a barrel after the Saudi-Russia news was short-lived, not least because of the failure of the two sides to reach any deal on output at a special meeting in Doha back in April.

    But the derivatives market shows that investors could well be holding out for a deal further down the line and are displaying a lot more optimism, as demand and supply come closer to falling into balance.

    The options market has seen a near-across-the-board rise in the implied volatility, a measure of the price, in buy options relative to sell options this week.

    "The overall situation in oil, in my view, is stabilising. The stock draw should be with us as we head into the fourth quarter," said asset manager RCMA's chairman Doug King, whose Merchant fund runs some $220 million in commodities.

    "One would say that there is a distinct chance in the next six months that we do get into some of the inventory, which would act as a catalyst for investors to increase exposure to the oil market"

    When supply is expected to outstrip demand in the longer term, buy, or "call" options tend to be cheaper than sell, or "put" options as investors generally bet on the greater likelihood of oil prices falling rather than rising.

    Puts are still pricier than calls, but by far less than they were just a couple of weeks ago, particularly those that are said to be close-to-the-money, or likely to be profitable.

    The premium of a put maturing in one month, around the time of the Algiers meeting, is around 422 basis points more expensive than a call expiring at the same time, compared with 550 basis points a week ago.


    A major sticking point at Doha was getting Iran to join any group initiative on production.

    Iran has said that while it supports joint efforts to stabilise the market, it will not freeze production until its own output reaches pre-sanctions levels of around 4 million barrels per day, from an estimated 3.6-3.8 million bpd now.

    "The timeframe to reach any agreement to freeze is not necessarily in September. It will need to include Iran and that will be more likely to be at the end of the first quarter of next year," Petromatrix strategist Olivier Jakob said.

    For puts maturing in May next year, when a supply agreement might theoretically materialise, their premium over calls has fallen to 570 basis points from 600 basis points last week.

    Money managers, who in early August had built the largest short position in crude futures since the start of the year, have now cut those bets in half.

    "Rebalancing is definitely taking place, to some degree or another. It's most definitely seen in the European market ... where inventories really have been coming down a great deal since the beginning of the year," said Christian Gerlach, who helps run around $350 million in commodity-related funds for Swiss & Global Asset Management, part of Julius Baer.

    OPEC and Russia are pumping at, or close to, record rates, while U.S. production has started to pick up after months of decline, making investors wary about the effectiveness of a freeze, especially given uncertainty over the global economy.

    Regardless of whether the market believes there could be any freeze, regular verbal intervention is paying off.

    From the first whispers of possible coordination in February, the price has risen by 51 percent and the premium of oil for delivery by December 2017 over that for December 2016 has slimmed down to $3.60, from closer to $5 a month ago.

    The International Energy Agency believes the market will show no oversupply over the second half of 2016.

    "We have no real spare capacity in OPEC at all. It's 'full blast'," RCMA's King said.

    "The stock situation gives a slightly false comfort just because there is no capacity spare around the world apart from U.S. shale and the question everyone will want answering is, at what price does this new supply meaningfully reappear?"
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    Russia energy minister predicts winter oil price drop

    Russia’s energy minister has said there was a risk oil prices would drop in winter due to market volatility, according to a media report.

    Alexander Novak told Russian news website TASS: “It is hard to forecast supply on the market due to contingencies that emerge. A risk of cheaper oil prices remains in general.

    “We used to say earlier that a balance between supply and demand of oil will be achieved only in 2017, and we stick to these forecasts.

    “In general, we expect that demand will rise by 1.1-1.3 million barrels (per day) compared to the previous year.”
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    Russian average oil output close to 11 mln bpd in Sept 1-7 - sources

    Russian average oil production was close to 11 million barrels per day (bpd) in the period of September 1-7, two industry sources told Reuters on Thursday.

    One of the sources said the increase was due to restored output volumes at joint projects, known as production sharing agreements, between some Russian and foreign companies, as well as other factors. Russian oil output was down to 10.71 million bpd in August from 10.85 million bpd in July.

    The increased output in September - which may not be sustained throughout the month - comes as Russia and Saudi Arabia are talking about cooperation to stabilise global oil markets.
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    Deep investment cuts will slow rebound for offshore oil services-Bourbon

    French oil services company Bourbon said on Thursday that any rebound in oil and gas prices will take a while to reach companies in the offshore marine sector because of deep cuts in investments during the prolonged oil downturn.

    Bourbon, whose fleet of about 513 vessels provides offshore services for oil and gas companies, said its net loss in the first half widened to 104.3 million euros ($117 million)compared with a net loss of 19.2 million in the same period a year ago.

    Adjusted revenues fell 21 percent to 599.2 million compared with the first half of 2015, the company said.

    "After the drastic reduction of the level of investments of oil and gas companies over the past couple years, oil producers are now thinking of the future, particularly to maintain their level of production in the medium term," the company said.

    "However, the inevitable rebound in activity will take some time to reach offshore marine services," it said in a statement, adding that deepwater and shallow water segments of the industry will continue to be affected by overcapacity of vessels.

    Bourbon said a rebalanced demand and supply outlook for the oil market in 2017 will have a positive effect on the company.
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    Strike threat at Norway facilities

    Strike risk: Hammerfest LNG plant

    Norwegian oil union Safe has warned of possible strike action by more than 800 workers at onshore facilities after it decided to reject a pay deal offered by employers.
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    Bloated, glutted and static, Asia's LNG market keeps disappointing

    The liquefied natural gas (LNG) industry has morphed from energy's golden child to black sheep in the last two years, with demand slumping just as supplies soars.

    While low prices are a boon for consumers, the lack of demand and lowered revenue will threaten the efforts of companies to recoup investments in LNG export terminals in the United States and Australia. Further, future projects will have a hard time gaining approval.

    Asia demand was expected to soak up this supply but the region has turned to alternative and cheaper fuels. LNG imports to Japan, the world's biggest consumer of the fuel, are down 5.3 percent for the first seven months of 2016, government data shows. Meanwhile, South Korea's imports in July dropped 15.2 percent from the same time a year ago.

    These numbers mirror the lacklustre global LNG demand growth that Dutch bank ING said was only 1.5 percent over the past five years.

    At the same time, ING said existing LNG exporters from the U.S., Australia, and Qatar plan to add 190 billion cubic metres (bcm) per year of liquefaction capacity by 2020, a 50 percent increase from current levels, taking total global capacity to 600 bcm a year.

    "To maintain current LNG utilisation rates, we need to see LNG demand grow at 7.6 percent between now and 2020," the bank said in a report on Wednesday.

    While coal and oil, LNG's competitors, have risen this year, LNG's ties to the fuels limit its gains. LNG's common price link with crude oil keeps a lid on gas while coal is a cheaper alternative for power generation than LNG.

    Once one of the hottest commodities, Asian LNG spot prices LNG-AS almost tripled between 2010 and 2014 to over $20 per million British thermal units (mmBtu), attracting huge investment and triggering new LNG trading desks opening from London to Singapore.

    But soaring output from Australia and the United States, as well as the general commodities slump, pulled LNG prices back by almost 75 percent to under $5.50 per mmBtu.


    Huge reserves off Africa's east coast, in the eastern Mediterranean, and in Canada are waiting to be developed, and current exporters like Qatar, Russia, Australia, and the United States have large reserves they could ramp up.

    Traders hope the glut will create a liquid LNG spot market, a much talked about affair that has not happened.

    Yet there are stumbling blocks here too. While some buyers including Japan's Jera - the world's biggest LNG importer - have said they want to reduce their long-term contract volumes in favour of more spot LNG trading, other importers remain reluctant.

    "We need security of supplies as we rely entirely on LNG imports, so long-term supply contracts suit us well. We don't like trading," said Jane Liao, Deputy Chief Executive at Taiwan's CPC Corporation, a top five global LNG importer, and an event in Singapore last week.

    Yet not all is doom and gloom. Sustained low prices along with spreading environmental awareness against the use of coal mean that LNG demand will rise, especially in economically growing Asia.

    "We're expecting total LNG demand to double by 2030, and for Asia to account for 40 percent of that demand growth," Steve Hill, Executive Vice-President for Gas and Energy Marketing and Trading at Shell, said at the FT Commodities Summit in Singapore this week.

    "China has the most significant upside potential in terms of gas demand. China's gas share is only around 6 percent. But that share will only grow from now so that's the market to watch in Asia," he added.

    Attached Files
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    India Gas Output Seen Rebounding to Peak by 2022 on Price Reform

    India’s efforts to revitalize natural gas exploration will help the country’s output rebound to peak levels in less than a decade, according to IHS Markit Inc.

    The country’s gas output peaked between 2010 and 2011 at about 5 billion cubic feet per day, according to Rebecca Keller, Singapore-based associate director at IHS. Production has declined since then in part due to aging fields, as well as a dearth of new discoveries by explorers discouraged by policies that were seen hampering profitability. Keller sees the country’s output returning to its peak level by 2022.

    Energy reforms from Prime Minister Narendra Modi’s government with a more liberalized pricing structure that allow companies to charge higher rates is one of the main reasons behind the expected recovery, she said. The nation’s cabinet approved measures earlier this year including a gas price cap linked to alternate fuels liquefied natural gas, fuel oil, naphtha and imported coal for deepwater development.

    “They’ve made a lot of progress on upstream policies this year, if they keep with this reform agenda they will see results,” Keller said in a phone interview Tuesday. “We have seen a few projects already sanctioned or players talking about sanctioning them, so we are seeing that response happening. But it takes a few years for these projects to start up even if they are sanctioned today.”

    State-run Oil and Natural Gas Corp. has embarked on its largest ever exploration campaign as it plans to invest about $5 billion in its block in the Krishna-Godavari Basin off the east coast of India to produce 530 million cubic feet a day of gas and 77,000 barrels a day of oil in about five years. Overall, the company plans to invest 11 trillion rupees ($166 billion) by 2030 to expand oil and gas production.

    Reliance Industries Ltd. and partner BP Plc are looking to produce 1 billion to 1.2 billion cubic feet a day of gas by 2022 from their east coast block after they develop three new fields, Sashi Mukundan, BP India unit head had said in August. Gas production from KG-D6 averaged about 307 million cubic feet a day in the April to June quarter, Reliance had said in a July 15 presentation. Production from the KG-D6 block, discovered in 2002, has tumbled since hitting a peak in 2010 of around 2.2 billion cubic feet a day.

    “India does have gas reserves that it could be tapping into,” Keller said.
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    EnQuest announces 2016 half-year report


    EnQuest is delivering against its strategic priorities in the continuing low oil price environment. Further action to reduce opex and capex has been accompanied by sustained strength in operations. High production efficiency has driven EnQuest's highest H1 levels of production, with a well implemented drilling programme and with first oil from the Kraken development on schedule for H1 2017.
    Production averaged 42,520 Boepd in H1 2016, strong growth of 43% on H1 2015, with production increases in every operated asset:

    UK production grew by 22%, before inclusion of production from the new Alma/Galia development. Malaysian production was also up by over 20%.

    Alma/Galia delivered an average net production of 6,433 Boepd in H1 2016. Post first oil optimisation of production levels has continued in H2 2016, including two well interventions and acid treatments. Following which, between 5 and 31 August gross Alma/Galia production averaged 18,785 Boepd.

    With the extended period of production build up for Alma/Galia, full year 2016 production guidance is now anticipated to be in the range of between 42,000 and 44,000 Boepd, around the lower end of previous guidance, at the mid-point representing strong growth of c.18% over 2015.

    Revenue of $391.3 million and EBITDA*** of $242.9 million, reflecting the strong operational performance. The $182.6 million of cash generated from operations was $99.3 million or 119% up on H1 2015, reflecting the production growth.

    Continued further reductions in operating costs, H1 2016 unit opex was ahead of target at $23/bbl, benefiting from additional cost saving initiatives, including savings from EnQuest's offshored procurement hub. Full year unit opex is now expected to be around the lower end of the $25-$27/bbl guidance; this reflects the impact of the Alma/Galia well interventions in H2.

    2016 EnQuest cash capex outflow is being reduced by a net c.$30 million, predominantly as a result of the further phasing of milestone payments.

    The Kraken development is continuing on schedule. EnQuest today announces a further c.$150 million decrease in full cycle gross project capex, in addition to the c.$425 million of cost reductions announced since project sanction, giving a new gross full cycle project capex cost of c.$2.6 billion. Sail away of the Kraken FPSO is expected in H2 2016, as planned, ahead of first oil in H1 2017.

    In July 2016, EnQuest announced that it was conducting negotiations for the farm out of a 20% working interest in the exploration and production licences in the Kraken Field, to the Delek Group. EnQuest will provide further details in the event either of transaction documents being signed or of it becoming apparent that a binding agreement cannot be reached.

    Scolty/Crathes is both ahead of schedule and under budget, with first oil now expected around the 2016 year end.

    Net debt at the period end, was $1,681 million.
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    Summary of Weekly Petroleum Data for the Week Ending September 2, 2016

    U.S. crude oil refinery inputs averaged over 16.9 million barrels per day during the week ending September 2, 2016, 315,000 barrels per day more than the previous week’s average. Refineries operated at 93.7% of their operable capacity last week. Gasoline production increased last week, averaging about 10.2 million barrels per day. Distillate fuel production increased last week, averaging over 5.0 million barrels per day.

    U.S. crude oil imports averaged about 7.1 million barrels per day last week, down by 1.8 million barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 8.2 million barrels per day, 7.4% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 607,000 barrels per day. Distillate fuel imports averaged 108,000 barrels per day last week.

    U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 14.5 million barrels from the previous week. At 511.4 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories decreased by 4.2 million barrels last week, but are well above the upper limit of the average range. Both finished gasoline inventories and blending components inventories decreased last week. Distillate fuel inventories increased by 3.4 million barrels last week and are above the upper limit of the average range for this time of year. Propane/propylene inventories rose 0.6 million barrels last week and are above the upper limit of the average range. Total commercial petroleum inventories decreased by 13.7 million barrels last week.

    Total products supplied over the last four-week period averaged 20.7 million barrels per day, up by 2.4% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged over 9.6 million barrels per day, up by 3.2% from the same period last year. Distillate fuel product supplied averaged 3.7 million barrels per day over the last four weeks, down by 0.1% from the same period last year. Jet fuel product supplied is up 6.1% compared to the same four-week period last year.

    Cushing down 430,000 bbl

    U.S. Gulf Coast crude imports fall to lowest weekly level: EIA
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    Alaska clouds rising US lower 48 oil production

                                                                         Last Week  Week Before  Last Year

    Domestic Production '000............... 8,458             8,488           9,135
    Alaska '000    ................................... 428                473              452
    Lower 48 '000................................ 8,030             8,015           8,683

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    Permian oil output could grow 300,000 b/d/year at current price range: Pioneer CEO

    Production in the Permian Basin, the US' most active oil play, could grow significantly at current or slightly higher prices, but boosting Eagle Ford and Bakken output requires a step change in crude prices, Scott Sheffield, CEO of major Permian player Pioneer Natural Resources, said Thursday.

    Located in West Texas and New Mexico, the Permian could add 300,000 b/d a year at a $47/b to $57/b WTI price to domestic supply, Sheffield said in webcast remarks at the Barclays 2016 CEO Energy-Power Conference in New York.

    "I don't think the Eagle Ford or Bakken at a price of $47 are going to start up," Sheffield said of those basins respectively sited in south Texas and North Dakota/Montana. "I think [they] will be flat at a $50 price," he said. "Once you get to $55-$60, I think the Eagle Ford and Bakken start up at that time."

    But Permian production, which is just under 2 million b/d, will grow at $50/b, even though US conventional oil will decline, he added.

    "You start moving toward $60, and it will take a year to get going, but the US could easily [incrementally] supply 500,000-750,000 b/d" annually, Sheffield said. "At $60, rigs will come back to work and the Eagle Ford and Bakken will take off."

    That volume growth level is "way too much" but it "could easily happen," depending on where crude prices go.

    Eagle Ford and Bakken production currently supply about 1 million b/d of oil each. But production in the plays has dropped in the last 18 months by about 700,000 b/d and 200,000 b/d respectively.


    The world may need some incremental US unconventional and shale supplies in 2018-2020, Sheffield said. But if those plays really gear up again they will produce "too much oil too fast," he said, since it takes several months to start and stop the growth engine.

    Longer term, "we'll see $80 again and maybe higher, but we'll see $30 and $40 again too," he said.

    Also, Sheffield believes the market may eventually add a $5/b to $10/b political premium to crude oil. The reason: Apart from the US, there are only four other countries that are really equipped to supply large volumes globally in a lower price environment -- Russia, Iran, Iraq and Saudi Arabia.

    The Permian could hold as much as 150 billion barrels of recoverable oil equivalent, about equally split between the eastern Permian known as the Midland Basin and the western Permian called the Delaware Basin.

    The Permian has produced about 35 billion boe to date, Sheffield said, during nearly a century of oil exploitation.

    The basin's oil output, which has largely stood still for several months, is forecast to start growing again either late this year or early 2017 since its rig count is climbing.

    Last month, the US Energy Information Administration reversed its projections for very slight declines in Permian oil output in recent months. For September, the agency projected a 3,000 b/d gain for the play, and some forecasters believe volumes are bound to further rise in late 2016 because of ramping activity in the basin.

    Since late April, industry has added 70 Permian rigs for a total 202 last week. Pioneer will add five rigs there in second-half 2016, for a total of 17.

    And with mergers and acquisitions in the basin picking up, its rig count could increase even more, Sheffield said. For example, just this week, EOG Resources announced it will acquire producer Yates Petroleum for $2.5 billion which nearly doubles its Permian acreage position.

    "It wouldn't surprise me if another 100 rigs are added in next 12 months," Sheffield said. "Every time a deal is done, people add three to five rigs. So the Permian could easily get up to 300 rigs."


    Aside from being the US' largest oil field, the Permian also produces about 6 Bcf/d of natural gas.

    Pioneer, which favours the Midland basin for its greater amount of infrastructure and less broken-up geology than the Delaware, has 800,000 Midland acres.

    The company plans to grow its total company-wide production -- which was 223,000 b/d of oil equivalent in the second quarter -- at 15%/year through 2020 at $46/b, he said.

    "We could do this for 10 years," Sheffield added.

    Midland's playing field is about 9 million acres, he said, whereas Delaware has about 5 million acres--a number that Sheffield said has likely increased by 500,000 acres because of the Alpine High discovery that Apache Corp., also a top Permian player, unveiled Wednesday.

    The find, located in remote southwest Reeves County, Texas, holds an estimated 3 billion barrels of oil in place and 75 Tcf of natural gas, Apache said.

    "It's basically on the western side of the Delaware, where most of us thought there was no oil and gas," Sheffield said. "They made a very, very important discovery."

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    LNG Investment Swings to North America - Global Capex to Total $284 billion

    The LNG industry is undergoing a dramatic transformation. North American activity (the majority of which is committed spend) is driving a return to growth in global capital expenditure. A wave of new LNG carrier newbuilds will also be required to support a huge increase in traded base-load LNG volumes.

    Douglas-Westwood's new World LNG Market Forecast 2017-2021 indicates global LNG expenditure will total $284 billion (bn) between 2017 and 2021. This represents a 50% growth compared with the preceding five-year period.

    Report author, Mark Adeosun, commented, 'Liquefaction terminals will remain the principal driver of expenditure with spend in the segment totalling $192bn. This will subsequently lead to a 42% increase in liquefaction capacity by the end of the forecast period. Despite challenging times for shipyards, with only four LNG carriers ordered in 2016 (YTD) - unit orders are expected to bounce back in the near-term. Over 150 additional carriers yet to be ordered are likely to be required for additional export capacity coming onstream in the latter years of the forecast. Overall we expect expenditure on LNG carriers will represent 19% of global expenditure.

    'As the final set of Australian LNG projects start operating in 2017, global LNG expenditure will be concentrated in North America. This regional swing in investment will result in the United States (US) & Canada accounting for 17% of global liquefaction capacity by 2021 - with capex totalling $105bn, 36% of global expenditure over the forecast period. Of the six liquefaction terminals in the US, four of the facilities are currently under construction, with additional trains to be added before the end of the period. Beyond the forecast, some export terminals currently in the planning and approval stages will continue to support expenditure. We have, however, taken a conservative view on additional projects, given the current economic climate, and expect many of the early-stage projects not to progress past the initial planning/consent phase.

    'Over the long-term, LNG demand will continue to grow, as countries seek to diversify their energy supply. It is expected that delays in committing to new nuclear capacity and limitations of renewable technology in base-load applications will support continued newbuild of combined-cycle gas power plants. This, in addition to declining local production in some key consumer nations, will be a compelling driver for continued investment in these capital intensive projects.'
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    More Montney assets hit market in wake of Seven Generations' Cdn$1.9bn deal

    Two Canadian producers are seeking to capitalize on the enduring pulling power of the Montney play by putting assets up for sale, according to CanOils' newest report focused on M&A activity in August.

    RMP Energy Inc. (TSX:RMP) and Chinook Energy Inc. (TSX:CKE) have healthy balance sheets and a good inventory of development assets. Both have extensive holdings in the Montney shale. They form the bedrock of the total 12,700 boe/d of publicly disclosed Canadian assets put up for sale in August 2016. The listings follow the recent Cdn$1.9 billion acquisition by Seven Generations Energy Ltd.'s (TSX:VII) of predominantly Montney assets from Paramount Resources Ltd (TSX:POU), which showed Montney assets can still attract strong interest for high value deals.

    RMP Energy Inc.

    The largest Canadian asset listing in August involved RMP Energy initiating a strategic alternatives process, retaining Scotia Waterous and FirstEnergy Capital Corp. The majority of RMP's production is derived from the Ante Creek and Waskahigan fields. RMP produces 8,425 boe/d (43% liquids) based on Q2 2016 production figures. The company owns 24.6 million boe of 1P reserves (36% liquids).

    Chinook Energy Inc.

    has also initiated a strategic alternatives review and has retained Peters & Co. as its exclusive financial advisor. Chinook is predominantly Montney-focused with 2,890 boe/d of production during Q2 2016 and 12.9 million boe (16% liquids) of 1P reserves. Chinook said it is open to expanding its core operations via acquisitions or by establishing a new core of operations. They will also entertain a merger, sale or JV with a well-capitalized entity to help develop existing assets.
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    Suncor Looks To Abandon Oil Sands Assets

    Canada’s largest oil producer is looking to abandon some of its high-cost and greenhouse gas intensive oil sands assets, according to Suncor Energy’s CEO Steve Williams.

    Williams mentioned the move at the Barclays convention in New York, stating: “We’ve begun to have conversations with the government of Alberta and the current regulators about the design of their policy, which actually requires the maximum amount of resource to be extracted regardless of the economic or environmental value.”

    Suncor wants to abandon the deposits in question in order to ease the effect of rules that were created to maximize the output from oil sands on land leased from the government. The plan to abandon the sites is being utilized as a cost-cutting measure not just by Suncor, but other oil companies as well who continue to look for money-saving measures in the face of declining commodities prices.

    Not only are the sites among the highest in carbon emissions, but they are expensive to run. That expense will only increase in the near future, since the province of Alberta is planning to double its carbon tax and has announced that it will cap the greenhouse gas emissions of tar sands operators at 100 million metric tons.

    Oil sands operations emit around 70 million metric tons per year, which is about a quarter of the emissions for Alberta. Operators are concerned about what effect the moves will have on their ability to develop their leases in the long haul.

    Despite the new measures, the government of the province has not explained how it will allocate any room left under the cap. In the past, the province has tried to maximize the production on its public lands so as to glean as much as it could from royalty payments.
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    U.S. refiners revamp operations as renewable fuel costs surge

    U.S. oil refiners, beset by the weakest profit margins in six years, have been laying off workers, revamping operations and ratcheting up pressure on regulators and lawmakers to tweak the renewable fuel program, whose costs have ballooned.

    The top 10 U.S. independent refiners look set to take a record hit on renewable fuel credits this year. They spent $1.1 billion on the credits in the first half of the year, just short of a record $1.3 billion in all of 2013.

    Refiners without operations dedicated to selling blended fuels to consumers, must purchase credits to prove compliance with U.S. clean-fuel mandates.

    These "merchant refiners" are required to blend biofuels like ethanol with gasoline or other petroleum products, or else meet those obligations by purchasing paper "credits" called Renewable Identification Numbers (RINs) in an opaque market.

    Meeting these standards once cost just pennies a gallon. But costs have risen in recent years and become a pressure point for independent refiners and fuel importers.

    Biofuels advocates and the EPA have said refiners ultimately recoup RIN costs by including them in the price of the products they sell.

    Federal regulators are due to finalize next year's mandates for biofuel use within months. Refining executives have long chafed at these requirements, and have been pointing to rising clean-fuel costs as one reason for cutting staff or overhauling operations while a glut of gasoline has squeezed margins.

    Ethanol RINs are "a much higher cost than they used to be. Add to that this low-margin environment, any which way a refiner can save costs, they are going to be doing it," said Timothy Cheung, vice president at ClearView Energy Partners in Washington.

    Trade sources said the situation has widened the divide within the petroleum industry between those who want to pressure regulators to tweak the existing program and those who want to push for a legislative overhaul.

    Philadelphia Energy Solutions Inc, a merchant refiner, on Wednesday told employees in a letter it was cutting benefits and seeking job cuts to offset renewable fuel costs. They, and other refiners such as HollyFrontier Corp have said regulatory costs are outpacing labor costs.

    "Refiners that are integrated into the retail space take money from their left pocket and put it to their right pocket - their retail arm - so they do not suffer. But merchant refiners don't have a 'right pocket'," PES CEO Phil Rinaldi said in the letter.

    In 2013, refiners' complaints of rising costs caused the Obama Administration to dial back biofuels targets, sparking criticism from advocates of ethanol and other renewable fuels.

    Refiners are pressuring lawmakers back from August recess to consider reforming the renewable fuel program. More than a decade old, the program has been a battleground between entrenched oil and corn interests. The U.S. Environmental Protection Agency has a Nov. 30 deadline to finalize next year's biofuels targets.

    Refiners like Valero Energy Corp have pressed regulators to tweak the program so more of the obligation rests with companies blending the fuel. These are often the larger integrated companies one step removed from the gasoline pump. That change would likely reduce costs for the merchant refiners.

    The alternative is for merchant refiners to increase their ability to blend ethanol. PBF Energy is the latest refiner to take this approach.

    PBF has asked Delaware regulators to expand its ethanol handling capacity at its Delaware City refinery to 420,000 gallons from 84,000 gallons to defray some of the renewable-fuel costs.

    PBF paid $160 million for renewable fuel credits in the first half of 2016, more than double the $72 million it paid in the first half of 2015.

    Also taking PBF's approach are the likes of Marathon Petroleum Corp and Tesoro Corp. Tesoro this week announced plans to produce a renewable biocrude to ultimately help meet its obligations.

    "Unlike others in our industry, we prefer to take rational, business-oriented steps to mitigate against risks posed by the RFS rather than write to, or file meaningless petitions for review with, the EPA," said Stephen Brown, vice president and counsel at Tesoro.
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    Total Exercises Its Pre-emption Rights on Barnett Shale Assets

    Total E&P USA today announced that it is exercising its pre-emption right to acquire Chesapeake’s 75% interests in the jointly held Barnett Shale operating area located in North Texas. Total E&P USA has owned the remaining 25% in the Barnett Assets since December 2009. With the preemption, Total E&P USA will be the 100% owner and operator of the assets.

    Properties in the proposed transaction include approximately 215,000 net developed and undeveloped acres, wells, leases, minerals, buildings and properties (the “Barnett Assets”). Associated 2016 net production is approximately 65 000 barrels of oil equivalent per day (boe/d).

    The preemption and associated transactions are subject to a number of conditions, including the receipt of third-party consents, and are expected to close in the fourth quarter of 2016.

    Under the terms of the transaction, Chesapeake will pay $334 million to Williams, the gatherer and processer of 80% of the gas from the Barnett Assets, to terminate its gathering agreement, projected Minimum Volume Commitment (MVC) shortfall payments and fees pertaining to the Barnett Shale assets. Total E&P USA will supplement Chesapeake’s payment with $420 million to Williams for a fully restructured, competitive gas gathering agreement, free of any MVC and with a Henry Hub-based gathering rate instead of a fixed per Mcf fee. Total E&P USA will also pay $138 million to be released from three midstream capacity reservation contracts.

    José Ignacio Sanz, President & CEO Total E&P USA commented: “Over the six years that we have been involved in the Barnett, we have gained an in-depth understanding of the play and the technology. With the new conditions created by the exit of Chesapeake and the associated restructuring of the midstream contracts, we believe that we can extract significant value from the substantial, well located resource base of the play by combining focused upstream operating efficiency, streamlined midstream contract management and marketing savvy through Total’s trading affiliate Total Gas & Power North America. As an operator, we look forward to working with all stakeholders, our leaseholders, the Dallas Fort Worth and other authorities, Williams and other midstream partners, and our customers. Increasing our stake in the Barnett shale supports Total’s global strategy to be a leader in natural gas.”
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    Williams Reorganizes to Focus on NatGas and “Drive Value”

    Williams continues to tread water as it is under assault by corporate raiders who want to toss out Williams management, fire a bunch a people and sell the company.

    We’ve chronicled the chaos endlessly. It seems like every day there’s something new in this soap opera.

    Here’s the latest: Williams announced yesterday the company is streamlining its operations by consolidating what is currently five business units into three units: (1) Atlantic-Gulf, (2) West and (3) Northeast Gathering & Processing. The stated purpose is to “advance a natural gas-focused strategy” and to “drive value.”
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    Alternative Energy

    Dong installs world's largest wind turbines off UK coast

    Dong Energy has installed the first of the world's largest wind turbines, which are taller and wider than the London Eye, at its Burbo Bank windfarm off the coast of Britain in the Irish Sea, it said on Thursday.

    The 32 turbines, made by Vestas, will each be able to generate 8 megawatts (MW) of electricity, stand 195 metres tall from sea level and have a rotor diameter of 164

    "This will be the first commercial deployment of the world's largest wind turbines," Benj Sykes, Dong's UK country manager for wind power, told Reuters.

    Combined, the 32 turbines will create enough electricity to power around 230,000 homes.

    The largest turbines currently installed, at Dong's Westermost Rough wind farm off the Yorkshire coast, in the North Sea, have a 6 MW capacity and are around 177 metres tall.

    Britain is seeking new electricity generation to replace its aging coal and nuclear power stations and has said around 10 gigawatts of offshore wind capacity could be installed by the end of the decade.

    The extension to the existing Burbo Bank wind farm, which comprises of 25 smaller 3.6 MW turbines, will likely be completed by the first half of 2017.

    "Using larger turbines is a critical part of the industry's drive in getting costs down," Sykes said.

    "Each turbine needs foundations, cables to an onshore substation and maintenance, so the more megawatts you can generate from each turbine, the lower the overall cost per MW."

    Dong has a target to drive down costs of offshore wind power to 100 euros ($112.48) per megawatt hour (MWh) by 2020.

    The Burbo Bank extension has already secured a minimum price for the electricity generated through Britain's contracts for difference (CfD) scheme of 150 pounds ($200) MWh for 15 years.

    Britain's government has said its next round of CfD renewable funding will focus on offshore wind, but the subsidies will be dependent on the wind industry's ability to drive down its costs.
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    Not Everyone Will Be Onboard If Potash Corp Acquires Agrium

    While it's true that the merger of equals being considered between PotashCorp (NYSE:POT) and Agrium(NYSE:AGU) won't run into many regulatory hurdles in Canada, that's not to say that everyone will be supportive of the two crop nutrition giants joining together. In particular, U.S. farmers would likely be outspoken critics of the deal.

    One-stop shopping

    PotashCorp and Agrium say they're discussing a merger, but nothing concrete is on the table. A deal might not happen. But if it did, Reuters reports that analysts at National Bank estimate the result would be a massive crop nutrient producer that controlled 62% of potash capacity, 30% of phosphate, and 29% of nitrogen.

    Pick up a bag of fertilizer and you'll see the letters N-P-K on the packaging, referring to the percentages of nitrogen, phosphorus, and potassium it contains. These crop nutrients are essential for plant growth whether in a backyard garden or on biggest commercial agricultural operations, and the trio of PotashCorp, Agrium, and Mosaic (NYSE:MOS) are the leading producers in North America. They also jointly own Canpotex, the potash marketing and distribution association that negotiates with foreign purchasers.

    It's because the three companies already work in concert in selling potash that many industry observers suspect a merger between PotashCorp and Agrium would have little impact on pricing, as their output would continue to go through Canpotex. And because both companies are Canadian, the deal wouldn't run afoul of the country's Investment Canada Act, which ultimately prevented Australia-based BHP Billiton (NYSE:BHP) from acquiring PotashCorp in 2010.

    Seeding the fields of doubt

    Potash -- and much of the rest of the fertilizer market -- is suffering from a period of depressed pricing that was brought on by the collapse of the commodities bull market, and then deeply exacerbated by the 2013 breakup of the other big international potash cartel, between the Russian and Belorussian producers. As the two vied for market share, supply outpaced demand, causing prices for the crop nutrient to plunge.

    Belorussian producer Belaruskali, which had been half of that cartel, recently signed contracts with India and China for potash at prices  30% below those from 2015, which were already discounted from the price when the cartel disbanded. The depressed market has caused producers to try to take capacity offline to balance supply with demand and bolster prices. BHP Billiton, for instance, may not move forward with its massive Jansen mine in Saskatchewan if the pricing environment doesn't improve, and Mosaic recently laid off 330 workers after suspending production at its Colonsay mine. PotashCorp has also temporarily closed some mines.

    What PotashCorp really wants

    Yet it's not so much Agrium's crop nutrient production PotashCorp is interested in: Agrium is also the largest farm retailer in North America, with $5.8 billion in reported retail sales in the second quarter. That's a 6% drop year over year, but the decline mostly stemmed from the lower prices crop nutrients were getting. Segment gross profits, on the other hand, were up 1.2% year over year, at near-record levels.

    Agrium's retail operations comprise more than 1,400 outlets, 63 terminals, seven plants, and 17 distribution centers in North America, South America, and Australia. They generated $12 billion in revenues last year -- more than three times the sales it generated from its global wholesale business, which produces, markets, and distributes all major crop nutrients for agricultural and industrial customers. It just announced it was acquiring two more retail operations that would add 34 more stores in the U.S. and Canada.

    PotashCorp doesn't have a retail network like that, and gaining access to Agrium's would help it weather the volatility of the commodities market better. Over the past five years, Agrium's stock has returned some 12%, while PotashCorp shares have experienced a 70% decline.

    Not a bumper crop of profits

    U.S. farmers, though, are already under pressure from their own low-pricing environment for their crops. Corn today goes for a little more than $3 per bushel, nearly half of what it was getting just a few years ago, while wheat has fallen by a like percentage. They're also being cornered by consolidation underway in the seed and chemicals markets: Syngenta is being acquired by China National Chemical; Dow Chemicaland DuPont are looking to merge; and GMO seed giant Monsanto (NYSE:MON) is being pursued byBayer.

    The Justice Department is also trying to thwart John Deere's (NYSE:DE) plan to acquire Monsanto's precision planting technology business for being anticompetitive, too, so a situation in which there were fewer companies from which to buy fertilizer and crop protection products doubtless wouldn't sit well with them. Canadian farmers probably wouldn't be ecstatic either.

    The deal may still get a pass from regulators because there are low-cost international suppliers, but the idea of Canadian and U.S. farmers being forced to shop for those vital supplies in Eastern Europe may not sit well. It could end up being the tractor lobby that causes this merger of equals to fall apart.
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    Bayer exploring sale of dermatology business to push forward its deal with Monsanto

    German chemicals and crop pesticides firm Bayer AG is exploring the sale of its dermatology business to push forward its deal with Monsanto Co, Bloomberg reported, citing sources.

    Bayer is working with JPMorgan Chase & Co (JPM.N) on the sale, which could fetch more than 1 billion euros ($1.12 billion), the report said. (

    Bayer said on Monday it was willing to offer more than $65 billion, a 2 percent increase on its previous offer for the world's largest seeds company Monsanto.

    The dermatology business could attract interest from existing makers of skincare products including Nestle SA's (NESN.S) Galderma, Allergan Plc (AGN.N) and Almirall SA (ALM.MC), as well as private equity firms, according to the Bloomberg report.

    Bayer and J.P. Morgan were not immediately available for comment.
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    Precious Metals

    Lundin Law PC Announces Securities Class Action Lawsuit against Goldcorp Inc.

    Lundin Law PC announces a class action lawsuit has been filed against Goldcorp Inc. concerning possible violations of federal securities laws between March 31, 2014 and August 24, 2016. Investors, who purchased or otherwise acquired shares during the Class Period, should contact the Firm in advance of the October 24, 2016 lead plaintiff motion deadline.

    To participate in this class action lawsuit, click here. You can also call Brian Lundin, Esquire, of Lundin Law PC, at 888-713-1033, or e-mail him [email protected]

    No class has been certified in the above action. Until a class is certified, you are not considered represented by an attorney. You may also choose to do nothing and be an absent class member.

    The complaint alleges that during the Class Period, Goldcorp made false and/or misleading statements and/or failed to disclose: that Goldcorp's mine in Penasquito was leaking selenium into the groundwater well near the mine as early as October 2013; that the Company informed the Mexican government about the rise of selenium levels in the groundwater in October 2014; that in August 2016 the Company informed the Mexican government of contaminated water found in other properties near the mine; and as a result of the above, Goldcorp's public statements were materially false and misleading at all relevant times. When this news was disclosed to the public, shares of Goldcorp decreased in value, causing investors harm.
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    Base Metals

    Indonesia evaluating mining rules as 2017 deadline on metal exports nears

    Indonesia's mining ministry is scrambling to find a way around a deadline on mineral processing that could prevent some miners, including U.S. copper mining giant Freeport-McMoRan Inc, from exporting minerals from the country from 2017.

    Under a government regulation introduced in 2014, miners of copper, zinc, lead, manganese and iron are restricted to exporting partially processed minerals until January 2017, after which only shipments of refined metals will be allowed.

    The export curbs - which have cost Indonesia billions of dollars in lost revenue - were intended to shift sales from unprocessed raw materials to higher-value finished metals, but smelters have been slow to materialise as low commodity prices have made them economically unviable.

    The government is now "comprehensively evaluating (the requirements) for each commodity," coal and minerals director general Bambang Gatot said on Thursday, referring to meetings on the rule with acting mining minister Luhut Pandjaitan.

    Uncertainty over Indonesia's mining rules have been a flashpoint between miners and the government for years. The sector accounted for almost 6 percent of Indonesia's GDP before the 2014 ban on metal ore exports, and has since slipped to about 4 percent.

    Also of concern to Jakarta, the government's non-tax revenue from mining missed its target by 43 percent last year.

    "There will definitely be a solution ... at least by January," Gatot said, noting that the government was discussing whether it needed to change the law or revise a regulation.

    Earlier this week, acting mining minister Pandjaitan said the government had been too slow in implementing domestic processing requirements mandated in Indonesia's existing 2009 mining law.

    "The implementing regulation only came in 2014, so there's no way they could build smelters (in time), and what's more commodity prices were down," Pandjaitan said.

    "Now we are trapped with how to continue applying the mining law properly. We can't change the law just like that," he said.

    The 2017 deadline would not apply to nickel ore or bauxite, exports of which have been completely banned since 2014.

    The rules on those ores were also "still being discussed," Pandjaitan said.

    The government has been rolling out new measures to re-energise Southeast Asia's largest economy after growth cooled to its slowest in 6 years in 2015, partly as a result of weaker returns from commodities.

    The government is also seeking new revenue sources, with a fiscal deficit expected to widen to 219 trillion rupiah ($16.8 billion) this year.

    Freeport, Indonesia's largest copper miner and an important source of government revenue, has said it is confident the government will not push ahead with the 2017 deadline, as the move could harm Southeast Asia's biggest economy.
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    Glencore, Origin put Chile hydropower business up for sale

    Glencore and Origin Energy have put their hydropower business Energia Austral in Chile on the block, with Standard Chartered advising on the sale, two people familiar with the process said on Thursday.

    Energia Austral includes three hydropower projects with a capacity of 1 000 MW, the biggest being the Cuervo asset at 550 MW, according to a flyer seen by Reuters.
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    Steel, Iron Ore and Coal

    NDRC loosens coal production restrictions

    Faced with surging coal prices, the National Development and Reform Commission (NDRC) will roll out a plan to allow some domestic coal companies to increase coal production under certain circumstances, domestic media reported on Thursday.

     The plan shows that the NDRC wants to balance domestic coal supply and demand, but is not willing to overly loosen its grip on the production of domestic coal companies by extending their annual working time, fearing that such a move might run counter to the government's goal of cutting overcapacity in the coal industry, experts told the Global Times on Thursday.

    "If the government loosens production restrictions too much, it might suppress the coal price, and the government does not want that to happen," Guan Dali, a coal analyst from the industry portal, told the Global Times on Thursday.

    The NDRC held a meeting on Thursday with representatives from a number of major domestic coal companies and workers from the China National Coal Association (CNCA), with an aim of stabilizing coal supplies and preventing coal prices from surging too quickly, according to a report from on Thursday.

        Surging prices

    The NDRC meeting convened at a time when China's coal prices are surging fast. The benchmark Bohai-Rim Steam-Coal Price Index (BSPI) rose to 515 yuan ($77.25) per ton by the end of Tuesday, compared with 494 yuan per ton at the end of August 30, the largest increase since the weekly index was released, according to a report by on Wednesday.

     According to a report from the Securities Times on Thursday, the price of thermal coal has surged by about 25 percent since the beginning of July, while the price of coking coal has risen roughly 30-90 yuan per ton in provinces like North China's Hebei Province and Shanxi Province in July.

    Lin Boqiang, director of the Center for Energy Economics Research at Xiamen University, told the Global Times on Thursday that the surging coal price was a result of the government's shortening of domestic coal mines' annual working days, which largely suppressed coal supplies.

    The NDRC stipulated in February that domestic coal mines can operate no more than 276 working days in one year, down from 330 working days in the past.

    About 1.9 billion tons of coal was produced in China from January to July, down 10.1 percent year-on-year, data from showed on August 31.

    According to Guan, as a result of the hot summer weather, electricity companies' demand for coal is increasing, but coal production and supplies are shrinking, which has resulted in a rise in coal prices in recent months.

    He also noted that the rainy weather around July blocked coal transportation corridors in certain regions such as Shanxi Province, causing some electricity firms to run short of coal.

    Striking a balance

    According to the report, dozens of domestic coal companies and coal mines will reach an agreement in the future under the guidance of the NDRC.

    The agreement stipulates that domestic coal companies and coal mines should increase their coal production when the BSPI reaches a certain level. But when coal prices fall back down, increasing production will have to cease and the government-demanded working days will be reinstated.

    Guan said that the BSPI lags a little behind the market price, but so far it is the most reliable parameter to formulate relevant policies in the coal sector.

    Lin stressed that the main objective of the NDRC's plan is to strike a balance between supply and demand, as well as prevent coal prices from fluctuating too greatly.

    The NDRC's decision runs counter to some market speculation that on Thursday it might allow domestic coal mines to resume working 330 days annually.

    According to Guan, returning to 330 annual working days for domestic coal mines might effectively suppress coal prices. "The government does want coal prices to rise, just not in a too abrupt manner," Guan said, adding that a rise in coal prices would help boost profitability for domestic coal companies.

    Guan also noted that if the government brings back the extended 330 working-day requirement, it might impact the efforts of cutting excessive capacities.

    "With the rising coal price, some private coal mines have already secretly restarted production," Guan disclosed.

    Zhao Chenxin, the spokesman of the NDRC, said at a press conference on August 16 that about 95 million tons of coal had been cut by the end of July, accounting for 38 percent of the yearly target for cutting excessive coal capacities.

    The CNCA couldn't be reached for comment, while an employee of the NDRC said he didn't know about the meeting when contacted by the Global Times.
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    China hits 60 pct of 2016 target for coal output cuts

    China has reduced its coal production capacity by 150 million tonnes in the first eight months of the year, representing 60 percent of its 2016 target for capacity cuts, state media said on Friday citing the state planner.

    The rate is nearly 1.5 times progress in the first seven months of 38 percent, Lu Junling, a senior official with the National Development and Reform Commission (NDRC), was quoted as saying at an industry meeting on Thursday to discuss market stabilization measures.

    The country is the world's top coal consumer but demand has been on the wane as economic growth slows and as the country shifts away from fossil fuels as part of a drive to curb pollution.

    China's coal producers have lobbied the government to approve a plan to increase output that could add 8-9 million tonnes per month of new supply from some 74 mines that produce high-quality clean coal.

    That was discussed at the meeting on Thursday and included a proposal that would allow producers to raise output if domestic prices hit certain levels, state-media Xinhua said.

    According to the proposal, selected mines would be able to increase average daily production by 200,000 tonnes if the benchmark price, the Bohai-rim steam-coal price index (BSPI), trades above 460 yuan per tonne for two weeks.

    That would rise to 300,000 tonnes of coal a day if prices go up to 480 yuan per tonne, and would increase to 500,000 tonnes if prices hit 500 yuan for two weeks, Xinhua said.

    The BSPI is currently at 515 yuan, according to industry website

    Any increases would be pulled if prices fall below trigger levels respectively at 460 yuan, 470 yuan and 490 yuan also for as long as two weeks.
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    Australia's thermal coal exports to drop in next 20 yrs

    Australia's thermal coal exports will probably face a sharp decline over the next 20 years, as countries worldwide steps up its attack on carbon emissions, the Australian reported.

    Australia's exports of thermal coal used for power generation will slump to 135 million tonnes by 2035, compared with 210 million tonnes this year, estimated Wood Mackenzie, a leading industry consultancy.

    Key markets in Asia, Europe, and the Americas are all expected to record sharp falls of demand, as they step up efforts to meet energy demand mainly through enhancing energy efficiencies, developing alternatives like nuclear power, renewables and battery storage.

    The seaborne trade of thermal coal is expected to collapse from 900 million tonnes this year to 527 million tonnes by 2035, which would also be a key factor in thermal coal's forecasted share of power generation diving from 41% in 2013 to 16%.

    Yet it is not all gloom for the Australian industry, the nation's higher quality coal will be more resilient compared with low energy lignite-type coals, said Prakash Sharma, director of Wood Mackenzie's global coal markets research.

    Australian thermal coal exports are expected to fall at a slower pace than other countries. Indonesian exports will decline from 340 million tonnes in 2016 to 193 million tonnes by 2035.
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    China Aug coke exports surge on year

    China exported 1.04 million tonnes of coke in August, surging 62.5% from a year ago, but dropping 5.45% on month, showed data from the General Administration of Customs (GAC) on September 8.

    Total value of the steelmaking material in the month rose 44.46% on year to $146.34 million, equivalent to an average export price of $140.71/t, up $8.02/t.

    Over January-August, China's coke exports amounted to 6.89 million tonnes, climbing 16.3% on year, with value dropping 15.4% on year to $844.28 million.
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